Friday, June 29, 2012

The islands of the Caribbean basin are predominantly net energy importers, with the exception of Trinidad and Tobago, which is a major exporter of liquefied natural gas (LNG). Venezuela provides a sizable amount of crude oil and refined products to its Caribbean neighbors at below-market prices and with favorable financing terms under the Petrocaribe initiative. Some islands are important centers for oil refining and storage, due to their proximity to the U.S. market.

Caribbean map

In recent years, there has been concern that higher global oil prices will impair the Caribbean economies, as they are highly dependent upon oil for their energy needs. In response, the island nations have been discussing ways to promote alternative energy sources and better integrate their energy sectors.

Thursday, June 28, 2012

U.S. refining capacity has always fluctuated, expanding or contracting with market conditions, changes in consumption patterns, and changes in product specifications. So has the corporate ownership of U.S. refineries, with some individual plants changing hands multiple times in their history. Last year was no exception: 2011 saw numerous refinery sales and several plant closures. There have already been additional changes this year, as the refining landscape continues to evolve, and further changes may occur before the end of the year.

The U.S. Energy Information Administration (EIA) keeps track of changes in U.S. refining ownership and overall capacity on an annual basis. According to the latest EIA Refinery Capacity Report released June 22, there were, as of January 1, 2012, 144 operable refineries in the United States with capacity totaling 17.3 million barrels per calendar day (bbl/d), 414,000 bbl/d lower than on January 1, 2011 (Figure 1). The decrease in capacity is mostly due to the closure of two refineries in Pennsylvania; Sunoco's Marcus Hook refinery and ConocoPhillips' Trainer refinery.

Looking into 2012, EIA completed detailed analyses of the potential impact of these refinery closures in its report Potential Impacts of Reductions in Refinery Activity on Northeast Petroleum Product Marketsreleased in February 2012, and Energy In Briefreleased in May 2012. Since the release of these reports, however, Delta Air Lines has agreed to purchase the Trainer plant, which has a capacity of 185,000 bbl/d. To date, there has been no determination as to when the refinery will once again operate. Meanwhile, Energy Transfer Partners agreed to acquire Sunoco, which earlier had stated it would close its Philadelphia refinery by August 1 if no buyer was found. Potential buyers have reportedly emerged for that plant, and its outlook remains unclear. Finally, it should be kept in mind the data as of January 1 do not reflect other important refinery capacity developments since the start of 2012, including the 325,000-bbl/d crude distillation expansion of the Motiva refinery in Port Arthur, TX, now clouded by an industrial accident that occurred in early June.

U.S. Refinery Capacity

While the amount of crude distillation capacity is the single most widely tracked capacity indicator, capacity for other types of refinery units can follow a different pattern over time, as refiners invest in specific types of capacity needed to support their desired input and product slates. Overall, 2011 saw a slight decrease in capacity for catalytic cracking, catalytic reforming and hydrotreating. This is due in part to the refinery closures on the East Coast, Petroleum Administration for Defense District (PADD) 1. However, vacuum distillation capacity, coking capacity and hydrocracking capacity increased. Expansions at WRB's Wood River, Illinois refinery and Total's Port Arthur, Texas refinery helped mitigate the PADD 1 declines.

Of the 144 operable U.S. refineries recorded by the EIA Refinery Capacity Report, 134 were operating and 10 were idle as of January 1, 2012. A refinery is considered idle if the atmospheric crude oil distillation unit (ACDU) is not in operation and not under active repair, but capable of being placed in operation within 30 days; or the ACDU is not in operation, but under active repair that can be completed within 90 days. Based on the definition above, refineries are considered to be idle if on January 1 they are not in operation for any number of reasons including routine maintenance, unplanned maintenance, or market conditions.

Refinery sales in 2011 included the merger of Holly Corp with Frontier Refining and Marketing, bringing HollyFrontier Corporation's total refinery capacity to 470,350 bbl/d. Murphy Oil Corporation sold both of its U.S. refineries last year. Valero Energy Corporation purchased Murphy's Meraux, Louisiana refinery, and Calumet Lubricants purchased its Superior, Wisconsin refinery. On May 1, 2012, ConocoPhillips split into two stand-alone, publicly traded corporations. The downstream operations and nine refineries in the lower 48 states will be owned by Phillips66, and the refinery in Prudhoe Bay, Alaska will remain under ConocoPhillips.

With the purchase of the Meraux refinery, Valero is once again the largest U.S. refiner, with total capacity of 1.863 million bbl/d as of January 1, 2012. ExxonMobil was a close second with 1.856 million bbl/d. ConocoPhillips fell to third largest while BP PLC and Marathon Petroleum Corporation ranked fourth and fifth, for the third consecutive year. These five companies make up 45 percent of total U.S. refining capacity.

On a PADD level, the top rankings by corporate capacity are mostly unchanged from the last two years. With the closure of Sunoco's Marcus Hook refinery, PBF Energy Corp now leads the East Coast (PADD 1) with 29 percent of its capacity. Marathon Oil Corporation leads in the Midwest (PADD 2) with 17 percent. ExxonMobil Corporation has 16 percent of the capacity in the Gulf Coast (PADD 3). In the Rocky Mountains (PADD 4), Suncor Energy Inc. leads with 17 percent of capacity, while Chevron Corporation has the most capacity in the West Coast (PADD 5) with 18 percent.

Gasoline and diesel prices fall again
The U.S. average retail price of regular gasoline decreased 10 cents this week to $3.44 per gallon, 14 cents per gallon lower than last year at this time. This is the 12th consecutive week that the average U.S. price has declined. Prices dropped in all regions of the Nation, with the largest decrease on the West Coast, where the price fell 14 cents to $3.82 per gallon. The Midwest price decreased 13 cents to $3.43 per gallon, while the Gulf Coast price dropped about seven cents to $3.20 per gallon. The average price on the East Coast and in the Rocky Mountain region both decreased about six cents, to $3.34 per gallon and $3.63 per gallon, respectively.

The national average diesel fuel price decreased five cents to $3.68 per gallon, 21 cents per gallon lower than last year at this time. This marks the 11th consecutive week that the average U.S. price has fallen. The West Coast saw the largest decrease for the fifth consecutive week, falling six cents to $3.84 per gallon. The price in all other regions of the Nation dropped about five cents. The average diesel price is now $3.72 per gallon, $3.61 per gallon, $3.60 per gallon, and $3.78 per gallon on the East Coast, Midwest, Gulf Coast, and Rocky Mountain regions, respectively.

Propane stocks show more growth
U.S. inventories of propane continued their seasonal growth last week, adding 1.8 million barrels to end at 61.4 million barrels, 57 percent higher than the same week last year. Most of the build in stocks occurred in the Midwest region, which added 0.9 million barrels. The Gulf Coast region grew by 0.5 million barrels, the East Coast was up 0.3 million barrels and Rocky Mountain/West Coast stocks grew by 0.2 million barrels. Propylene non-fuel-use inventories represented 6.1 percent of total propane inventories.

Tuesday, June 26, 2012

Global crude oil production capacity is likely to climb from 93 million b/d currently to 110 million b/d by 2020 in the largest single-decade increase since the 1980s, a former senior Eni executive forecasts in a new study.

The 17 million b/d surge will occur nearly everywhere, with the largest increases in Iraq, the US, Canada, Brazil, and Venezuela, said Leonardo Maugerie, a research fellow at the Geopolitics of Energy Project at the Belfer Center for Scientific and International Affairs at Harvard University’s John F. Kennedy School of Government.

“What’s happening in North Dakota, particularly in the Bakken and Three Forks formations…and the Eagle Ford in Texas is the beginning of a big revolution, probably the biggest we’ve seen in the oil industry in decades,” Maugerie said.

Tight oil production in the two states has grown from virtually nothing in 2010 to 1 million b/d, “which is incredible by any standard,” he continued. The combination of hydraulic fracturing and horizontal drilling will make it possible to exploit US tight oil plays, “and there are plenty,” and open up a new era, Maguerie said. “By 2020, thanks to production from tight oil formations, the United States could be the world’s second oil producer in the world after Saudi Arabia,” he said.

Price implications

Maguerie said increased global production potentially could make prices collapse. Investments could sustain the 20% production capacity increase if price stay at or above $70/bbl, he explained. But with world demand sluggish due to the sluggish economy and growing emphasis on energy efficiency, a significant dip or even a collapse in prices is possible, he said.

“If I’m right, and this new production makes its way onto the market, we will face sooner or later a collapse of oil prices,” Maguerie said. “Depending on [its] timing, the consequences could be short-term or long-term.”

Major emissions reduction technology investments will need to accompany this coming oil boom to respond to growing enforcement of regulations, the study indicated. New oil production projects could be stymied or delayed without a balance between industry and environmental interests, it said.

Maguerie said his study was unique because it began with a huge proprietary base of the world’s existing oil fields, a field-by-field analysis of investments, and production targets from those investments. “Then I made my assumption about risk factors, depletion, and reserve growth,” he said.

“It’s a kind of bottom-up analysis that is unique because usually this kind of study is based on macroeconomic, econometric models and not on the reality of the bottom-up production under way,” he said.

Thursday, June 14, 2012

For all the turmoil surrounding the American solar industry, the U.S. followed up its record fourth quarter of 2011 with its second-strongest quarter yet.

According to new figures released by GTM Research and the Solar Energy Industries Association (SEIA), 506 megawatts (MW) of new installations came online during the first quarter of 2012. That robust figure followed the American industry’s record-setting 780 MW that came online between October and the end of December, and it puts it on pace to easily surpass last year’s installation mark.

The new numbers are increasingly meaningful as the industry looks to assess the fallout from a string of potential market disruptions. The Section 1603 grant expired at the end of 2011 and the low-cost Chinese panels driving much of the U.S. industry were recently hit with hefty tariffs, the largest of which dates back to February of this year.

But so far, so good from an installation perspective as an 85 percent growth over the first quarter of 2011 has increased confidence that the industry will maintain its momentum through 2012. The better-than-expected first-quarter figures has led GTM Research to bump up its 2012 projections by about 15 percent to 3.3 gigawatts (GW), which would represent a big leap over the 1.8 GW installed in 2011. From there, the projected growth is relatively flat in 2013 as the impacts of the 1603 expiration and the new tariffs finally catch up with the industry. But strong growth is still projected for 2014 (about 5.3 GW), 2015 (about 6.6 GW) and 2016 (about 8.4 GW) as the U.S. emerges as a global market leader.

U.S. installed solar power

The readjusted 2012 outlook, coupled with expected declines in the European market, would push U.S. market share into double digits at nearly 11 percent. This would be up from 7 percent in 2011 and 5 percent in 2010, and it’d make the U.S. the fourth largest global PV market. The upward trajectory would also make it one of four large-scale international markets with expected long-term growth, with the others being China, India and Japan.

Two major factors helped fuel U.S. installation in the first quarter, according to the report. At least 1 GW of modules were “safe harbored” at the end of 2011, a common strategy used to qualify modules and inverters for the 1603 grant ahead of its expiration. Many of those modules were deployed during the first quarter of 2012. While the smaller countervailing duty was announced during the first quarter, the much larger anti-dumping tariff wasn’t announced until May. The first quarter was marked by uncertainty and new strategies to avoid penalties. The report notes that anecdotally, some Chinese suppliers became the importer off record, so they could absorb the tariff themselves and sell “tariff-proof” modules. Still, many developers have shifted some procurement to non-Chinese producers.

The role of American panel manufacturing has taken center stage in the political fight surrounding the solar industry. From that perspective, the first quarter proved to be disappointing as U.S. solar panel production amounted to 160 MW, less than half the amount produced during the first quarter of 2011.

Other key takeaways from the report include:

New Jersey was the largest state market, with 174 MW of installations in Q1 2012.

Blended module prices for Q1 2012 were down to $0.94/W, a staggering 47 percent lower than Q1 2011 levels of $1.78/W.

Utility-scale installations, which accounted for more than half of the 2011 fourth-quarter figures, represented a much smaller percentage in the first quarter of 2012. Utility installations reached 124 MW in the first quarter. Most of the utility-scale installation is expected to come during the second half of the year, and GTM Research is 1.8 GW to come online by the end of the year

Cumulative operating PV capacity in the U.S. now totals 4.4 GW.

A total of 1.1. GW of concentrating solar power (CSP) is now under construction.

Abengoa’s Solana Generating Station received a $125 million investment from Capital Riesgo Global, a subsidiary of Banco Santander, for an equity stake in the CSP project.

Construction of the CSP power tower at the Crescent Dunes Solar Energy Project was completed in February 2012.

Wednesday, June 13, 2012

Canada has been a significant component of the global energy trade due to its proximity to and trade with the largest energy consumer in the world, the United States. Canada maintains a surplus in all sellable energy commodities, exporting crude oil, natural gas, coal and electricity. The country is the most significant source for U.S. energy imports. The United States has traditionally provided the markets for Canada's energy exports. However, Asian countries are seeking greater access to Canada's natural resources to fuel Asia's own long-term economic growth.

Tuesday, June 12, 2012

Over the course of two decades Vietnam emerged as an important oil and natural gas producer in Southeast Asia. Vietnam has boosted exploration activities, allowed for greater foreign company investment and cooperation in the oil and gas sectors, and introduced market reforms to support the energy industry. These measures have helped to increase oil and gas production, but the country's rapid economic growth, industrialization, and export market expansion have spurred domestic energy consumption. The country's real gross domestic product (GDP) grew by an average of 7.2 percent per year in the last decade.